TMX at One Year: Why the West Coast Is Not the End of the Line

By Eric Lingman and Vaughn Hulleman

When the Trans Mountain Expansion (TMX) project launched in May 2024, it marked a long-awaited milestone for Western Canadian crude producers. The expectation was that with an additional 590,000 barrels per day (bpd) of pipeline or takeaway capacity, Canadian heavy crude[1] prices would strengthen, new markets would open, and long-standing pipeline infrastructure constraints would be alleviated. Just prior to TMX’s commissioning last year, Stillwater predicted that some of the TMX heavy barrels would be placed in California. Turns out, we got that right, but just over a year later, the market story has taken an intriguing turn.

TMX Barrels & PADD 5 Crude Rebalancing

As illustrated in Figure 1 below, starting in May 2024, TMX-delivered heavy crude ramped up quickly in PADD 5 (i.e., the West Coast) while Middle Eastern grades were almost completely backed out, and South American heavy crudes declined somewhat.

Figure 1. Heavy Crude Imports to PADD 5 (bpd)

TMX Pricing & West Coast Price Impacts

Since TMX startup in May 2024, the price of the key heavy crude benchmark, Western Canadian Select (WCS), has strengthened as expected (see Figure 2) due to the increased TMX takeaway capacity. In late 2024, WCS at Hardisty was trading at a discount to West Texas Intermediate (WTI) ranging from U.S.$ 9-12 per barrel (bbl) – approaching pre-startup expectations. The steep increase in differentials seen in January 2025 was due to the threat of a 10% tariff on Canadian energy resources imported into the U.S. That threat had significant impact on North American crude oil markets, including WCS and Alaskan North Slope (ANS), a major West Coast crude grade. The specter of tariffs increased market uncertainty, and the possibility of further tariff escalations or retaliatory measures temporarily cratered western-sourced crudes. The markets feared that tariffs would negatively impact U.S. demand for heavy Canadian crude, and crude prices moved lower to compensate. When the threat of tariffs on Canadian energy were not acted on, prices recovered quickly.

Figure 2. WCS and ANS Differentials to WTI (US$/barrel)

*Note that ANS pricing tracks WCS at about a $10/bbl premium. With WCS serving as a key benchmark for heavy sour crudes in North America, its price movements influence other similar heavy crude grades, resulting in this mirrored price relationship.

West Coast Crude Competition

What TMX may have unexpectedly done is reveal to refiners just how much more competitive the heavy crude market on the U.S. West Coast has become with the startup of TMX. At first blush, refiners on the U.S. West Coast should be seeing higher costs for heavy Canadian crudes and ANS. But, for heavy Canadian crudes to gain West Coast access and for ANS to retain its share, they must compete on delivered price with other imported heavy grades from the likes of Venezuela, Ecuador, and Columbia. This increased competition puts downward pressure on U.S. West Coast prices and netbacks to Canadian producers. However, heavy Canadian crudes also access the U.S. Gulf Coast (via the Enbridge and other pipeline systems) and heavy crude demand in that market has increased with the startup of the new Pemex Dos Bocas/Olmeca refinery in Tabasco, Mexico. It will be interesting to see which coast will dominate in setting the Hardisty price going forward.

Why hasn’t all the TMX heavy been placed in California?

What’s initially puzzling, is that despite low freight cost and ample coker capacity on the U.S. West Coast (420,000 bpd; more than enough to absorb all the additional volumes from a completely full TMX) more than half of the TMX barrels are flowing to Asia. These flows challenge the assumption that crude moves along the shortest, cheapest path.[2]

So, if the U.S. West Coast is close, well-equipped, and capable, why are half of the heavy barrels transported on TMX heading across the Pacific? Some could point to freight cost advantages for Asia-bound cargoes that leverage economies of scale from transloading light-loaded (~550-thousand-barrel) Aframax cargoes onto very large crude carriers (capacity: 2 million barrels) at offshore lightering zones like California’s Pacific Area Lightering (PAL).This method allows TMX shippers to move crude to Asia for about $5/BBL — cheaper than sending a single Aframax (~$6-8/BBL) the entire distance. This strategy has become more common since mid-2024, with major Chinese buyers looking for ratable supply of heavy crudes taking advantage of the freight economies of scale.

Figure 3. TMX PADD 5 / Asia Split (million barrels per day)

But while this freight logic helps explain how barrels are reaching Asia efficiently, it doesn’t fully explain why so few barrels are staying on the U.S. West Coast. Although it is an active and openly traded crude market, the U.S. West Coast sees many well-established crude grades that are a good match to the region’s refinery configuration. With the West Coast’s crude refining capacity of 2.3 million barrels per day, it’s a zero-sum arena where every new heavy Canadian barrel must displace an existing one. The primary incumbents – ANS, Colombian, Ecuadorian, and Middle Eastern grades – are well ensconced and will not be easily displaced.

Overcoming PADD 5 Hurdles

Of course, heavy Canadian must compete not only on freight but also on yields and quality. If not discounted sufficiently to justify refiners making operational adjustments or reworking existing supply relationships, Canadian heavy won’t win a valuable U.S. West Coast slot. Indeed, since TMX went live, Middle Eastern grades have been backed out perhaps because they were purchased on flexible spot arrangements rather than on term contracts. To take that slot, heavy Canadian crude had to become a more attractive option than, say, discounted heavy Ecuadorian and Columbian crudes, which have few alternatives to U.S. West Coast markets. This price interplay could be the key reason why more heavy Canadian crude has not come to the West Coast.

Another potential reason for seeing fewer Canadian heavy barrels moving south into PADD 5 is that most heavy Canadian crudes are dilbit crudes comprised of bitumen cut by 20-30% with light ends creating a high-volatility crude. But high-volatility crudes can cause crude unit overhead flooding problems and derate overall refinery throughput, negatively impacting refining crude margins if not blended properly with other low volatility crude offerings. Heavy Canadian crudes are also acidic (high TAN) and could cause reliability and maintenance issues. Finally, for refiners making calcined coke, heavy Canadian crude would provide a challenge to meet coke sulfur, nickel and vanadium specifications. All these operational issues can be mitigated if the delivered cost of heavy Canadian crude compensates for their impact, but these concerns may still have limited the West Coast appetite for TMX crude. There also may be a processing learning curve that will improve West Coast demand for heavy Canadian as refiners gain more experience in the coming months.

Meanwhile, Asian buyers – especially the low complexity teapot refiners in China – would be looking to take smaller, opportunistic, highly discounted volumes of TMX crude needing to be blended with lighter, sweeter crudes. Unlike U.S. refiners who may be bound by long-term relationships or slower crude slate turnover, many of these Asian buyers operate heavily in the spot market. The most likely TMX buyers, however, will be the large integrated state-owned refineries and petrochemical complexes with resid upgrading. In general, refiners with higher complexity and deep-water marine access will be looking to term up long-term ratable supply agreements with Canada, the most stable and reliable producing country. Asian spot and term demand appears to be drawing heavy Canadian barrels increasingly toward Asia.  We will have to see in the coming months.

In summary, the U.S. West Coast has shifted from being a theoretical natural destination of TMX barrels to being a contested middle ground. Despite its proximity and low freight cost, it can no longer be seen as a surefire TMX crude destination – and for now, heavy Canadian crudes have more consistent demand and perhaps a better home across the Pacific.

High-Carbon Heavy Canadian into Low-Carbon California??

For market participants who are deeply involved with the Low Carbon Fuel Standard (LCFS) in California, the insights shared above may seem a bit counterintuitive. Indeed, the influx of heavy Canadian crude via TMX would raise the carbon intensity (CI) of the average crude slate in California – running contrary to the goal of that program. The resulting impact on CARB gasoline and diesel prices under the LCFS, however, is relatively modest – typically only a few cents per gallon. This marginal price increase is likely to be outweighed by other market factors, including crude differentials and refinery yields. Assessing the magnitude of these nuances requires a deep understanding of West Coast crude quality, carbon accounting, and compliance pathways – areas where Stillwater Associates brings extensive expertise. Our analytical work has consistently helped clients navigate the complex interplay between crude sourcing strategies and LCFS price impacts. Contact us today to learn more.